Method of killing a well using a completion and kill valve

ABSTRACT

A completion and kill valve adapted to be placed immediately above a packer in the well production tubing including a tubular member having an inner bore and a circulation channel therein permitting communication between the inner bore and the well annulus area adjacent the exterior of the tubular member. A movable sleeve closes or opens communication through the circulation channel in response to various pressures and a spring bias acting on the sleeve. Provisions for locking the sleeve in the open position and subsequently unlocking the sleeve in response to inner bore pressure are provided.

United States Patent 1191 Mott July 9, 1974 [54] METHOD OF KILLING A WELL USING A 3,044,553 7 1962 Bradley 166/184 3,130,782 4 1964 Rike 166/313 COMPLETION AND KILL VALVE 3,395,758 8/1968 Kelly 8! al 1. 166/224 James D. Mott, Houston, Tex.

Hydril Company, Los Angeles, Calif.

Filed: Apr. 9, 1973 Appl. No.: 349,010

Related US. Application Data Division of Ser. No. 138,947, April 30, 1971, Pat. No. 3,750,752.

[75] Inventor:

[73] Assignee:

US. Cl 166/244 R, 166/184, 166/224 Int. Cl E21b 41/00 Field ofSearch 166/244, 154, 224, 184,

References Cited UNITED STATES PATENTS 5/1933 White 166/154 8/1953 Miller 166/244R Primary Examiner-James A. Leppink Attorney, Agent, or Firm-Pravel, Wilson & Matthews 57] ABSTRACT 16 Claims, 9 Drawing Figures PATENIEDJUL 9 1 3,822,745

- SHEET 2 [1F 5 METHOD OF KILLING A WELL USING A COMPLETION AND KILL VALVE CROSS REFERENCE TO RELATED APPLICATIONS This is a division of application Ser. No. 133,947, filed Apr. 30, 1971, and now U.S. Pat. No. 3,750,752 issued Aug. 7, 1973.

BACKGROUND OF THE INVENTION The invention relates to the field of a completion and kill valve.

One of the problems in completing a well has been removing heavy drilling mud from the production tubing to allow hydrocarbons within a formation to flow into the production tubing and on to the surface. A prior approach has been to use a swabbing tool in the production tubing to draw the drilling mud to the surface. Swabbing was costly, time consuming and dangerous. For example the drilling fluid brought to the surface made the working area slippery and unpleasant. Nitrogen injection has also been used to complete a well by lowering the density of the drilling mud in the production tubing and allowing the hydrocarbon pressure to overcome the hydrostatic head of drilling fluid. This method was also costly and time consuming as well as requiring special services and equipment.

Other devices to complete a well have permitted circulation of a light fluid down the production tubing with the heavy drilling fluid returning up the annulus, but these devices have required that hazardous wire line, packer or tubing work be done under pressure in either opening or closing the device.

Prior art attempts to kill a well by filling the production tubing with drilling fluid back circulated from the annulus into the tubing have also entailed wire line work under pressure or moving the well head or packer with formation pressure on the tubing in either opening or closing the device.

SUMMARY OF THE INVENTION This invention relates to a new and improved completion and kill valve, including a tubular member adapted to be mounted in a production tubing in a well and having an inner bore communicating with the inner bore of a production string. The tubular member includes a circulation channel therein for permitting communication between the inner bore of the tubular member and the well annulus and a movable member mounted with the exterior of the tubular member which moves in response to a continuous urging means in addition to differential pressures acting on various portions of the movable member to close and open the circulation channel to communication therethrough. A movable, releasable latch member moves to a locking position in response to inner bore pressure communicated through a locking channel for fastening the movable member or sleeve in the open position and moves to a free position in response to inner bore pressure communicated through a sensing channel for releasing the sleeve to thereby enable the sleeve to return to pressure responsive operation.

An object of the present invention is to provide a new and improved completion and kill valve for tubing.

A further object of the present invention is to provide a new and improved completion and kill valve wherein the well may be recompleted after killing.

Yet still a further object of the present invention is to provide a new and improved completion and kill valve which may be locked open in response to surface controlled pressure.

Yet still another object of the present invention is to provide a new and improved completion and kill valve which may be unlocked in response to surface control pressure.

BRIEF DESCRIPTION OF THE DRAWINGS FIG. I is a perspective view of the completion and kill valve of the present invention positioned in a single completion well production tubing;

FIG. 2 is a perspective view of the completion and kill valve positioned in a dual completion well production tubing;

FIG. 3 is a perspective view of the employment of a plurality of completion and kill valves in a multiple, for example, triple completion well production tubing;

FIG. 4 is a partial cross-sectional view of the completion and kill valve of the present invention;

FIG. 5 is a view similar to FIG. 2, illustrating the valve of the present invention maintained closed by outer pressure;

FIG. 6 is a view similar to FIG. 4, illustrating the valve of the present invention in the open position;

FIG. 7 is a view similar to FIG. 6, illustrating the valve of the present invention in the locked open position;

FIG. 8 is a view similar to FIG. 7, illustrating the valve of the present invention in the locked open position prior to unlocking;

FIG. 9 is a view similar to FIG. 4, illustrating another embodiment of the present invention.

DESCRIPTION OF THE PREFERRED EMBODIMENT As illustrated in FIGS. 1, 2 and 3, the completion and kill valve of the present invention is generally illustrated by the numeral 10 and is connected in a tubular production string or conduit T above a packer P as is well known in the art. The production string T is positioned in a well casing 11 located in a subsurface for mation F for recovery of hydrocarbons within the formation F through perforations O, as is well known in the art.

As illustrated in FIG. 4, the completion and kill valve 10 is illustrated in more detail and includes a tubular member 15 which is connected through the usual box and pin threaded connection 16 and 17, with the production string T.

The tubular member 15 is provided with an inner bore or channel 20 which communicates with the inner bore or channel 21 of the production tubing T. The inner bore 20 of the tubular member 15 includes a larger diameter upper portion 200, a shoulder 20b and a smaller diameter portion 20c.

A circulation channel 25 is formed through the wall of tubular member 15 above the shoulder 20b for permitting communication between the inner bore 20 and the area adjacent the exterior of tubular member 15.

A movable member 30 is mounted with the tubular member 15 and adapted to be slidably positioned in an member 30 includes an upper portion 30a and a lower portion 30b forming a sleeve concentrically mounted with the tubular member 15 exterior adjacent the channel 25. The portions 300 and 30b are secured together by engagement of thread portions 300 and 30d, respectively. The inner surface of sleeve 30 forms a chamber defined by a lower small diameter portion 300, a first annular tapered shoulder 30f, a lower larger diameter portion 30g, a locking recess 30h, an upper larger diameter portion 301', a second annular tapered shoulder 39], upper small diameter portion 30k, and sealing surface 30m.

An enlarged outer portion 150 of the tubular member 15 extends into the chamber to serve as a stop and a guide for the sleeve 30. A tapered annular surface 15b located adjacent the circulation channel 25 limits the downward movement of the sleeve 30 by engaging shoulder 30] of the sleeve 30 in the closed position, as illustrated in FIGS. 4 and 5. Outer surface 15c of the enlarged portion 15a is located closely adjacent upper surface 301' to assist in guiding the sleeve 30 in the sliding movement. The sleeve 30 further includes a flow port 30 therein having a smaller flow area than the channel 25 for permitting communication through the sleeve 30 between the area adjacent the tubular mem ber 15 exterior surface adjacent the circulation channel 25 and the annulus 12 exterior of the sleeve 30 when the sleeve is in the open position. The flow port 31 is sealed from communicating with the circulation channel 25, blocking flow through the circulation channel 25, when the sleeve 30 is in the closed position. The sleeve 30 is slidably sealed to the exterior of tubular member 15 at the upper end by a pair of O-rings 30n. The sleeve 30 is also slidably sealed to the tubular member 15 adjacent portion 15a by a pair of O-rings 15d. The lower small diameter portion 30a is slightly larger than the tubular member 15 forming an annular passageway between the tubular member 15 and the portion 306 for communicating the annular pressure adjacent tubular member 15 to a slide member 40.

The movable sealing slide 40 is a ring-shaped member mounted with the tubular member 15 exterior surface and concentrically positioned between the sleeve 30 and the tubular member 15. The member 40 is free to slidably move with respect to both the sleeve 30 and the tubular member 15 between a lower or extended position, illustrated in FIG. 4, and an upper or retracted position, illustrated in FIGS. 5, 6, 7 and 8. The member 40 includes a first annular step shoulder 40a and a second tapered annular shoulder 40b adopted to engage shoulder 30] of the sleeve 30 for a purpose to be described more fully hereinafter. The slide 40 moves to the retracted position in response to the annulus pressure adjacent the tubular member communicated through the annular passageway between the tubular member 15 and the portion 30e of the member 30 acting on the shoulder 40b of the member 40. A pair of rings fsea] an inner diameter surface 400 of the slide 40 to the tubular member 15. Another pair of O-rings 40:: seal an outer diameter surface 40 d of sealing member 40 to the sleeve 30. An O-ring 40d also seals the member 40 to the sleeve 30 when the tapered shoulder 40b engages shoulder 30f limiting the area of shoulder 30f communication with the annulus 12 pressure when the shoulders 40b and 30]" are engaged.

As illustrated in FIGS. 4, 5, 6, 7 and 8, a means for biasing movable member 30 to the closed position is provided by spring 41. The spring is positioned within the chamber between the sleeve 30 and the tubular member 15 and is retained in such position by retainer member 41 mounted with tubular member 15 and the shoulder a of the sealing member 40. The engagement of the sleeve shoulder 30f by the sealing member shoulder 40b acts as a carrying means carrying the sleeve 30 to the closed position as the closing biasing of the spring 41 moves the slide 40 to the lower position.

A sensing channel 45 is formed through the wall of tubular member 15 below the circulation channel 25 for permitting communication from the inner bore 20 of the member 15 into a portion of the chamber above the shoulder 40a of the movable sealing member 40. The sealing member 40 is maintained in the extended position, illustrated in FIG. 4, in response to greater pressure in the inner bore 20 communicated through sensing channel 45 to the shoulder 40a. This also maintains the sleeve 30 in the closed position.

As illustrated in FIGS. 4, 5, 6, 7, 8 and 9, a means for locking the sleeve 30 in the open position includes a slidably movable ring shaped latch member posi tioned between the sleeve 30 and the tubular member 15 and having a locking shoulder 50a and a stepped and partially tapered unlocking shoulder 50b. The latch member is movably mounted with respect to both the tubular member 15 and the sleeve 30 between a lower or locking position and an upper or free position. The latch member 50 moves downward to the latch or locking position, illustrated in FIGS. 7 and 8 in response to increased inner bore pressure urging on locking shoulder 50a and upward to the free position, illustrated in FIGS. 4, 5 and 6, in response to increased inner bore pressure urging on unlocking shoulder 5012. A pair of O-rings 50c and 50d seal the latch member 50 to the tubular member 15 exterior surface and the surface 301' of the sleeve 30, respectively. The fastening means further includes a shear pin 51 for maintaining the latch member 50 in the upper position and a split spring radially expansible detent ring 52 positioned below the latch member 50. The detent 52 is adapted to move into the recess 30h of the sleeve 30 when the sleeve moves into the open position and is locked in the recess 30h by latch member 50 moving downward within the radially expanded ring 52.

A locking channel 55 is formed through the wall of the tubular member 15 at a location between the sens ing channel 45 and the circulation channel 25 for permitting communicating from the inner bore 20 of the tubular member 15 through the locking channel 55 into a portion of the chamber above the locking shoulder 50a of locking member 50. Shoulder 50b of the latch member 50 is positioned in the chamber above the sensing channel 45 for communicating with the inner bore 20 through the sensing channel 45. The locking channel 55 and the sensing channel 45 are blocked from communicating in the chamber by the O-rings 40d and 50d.

A plug or means for controlling communication of pressure in the inner bore 20 to the desired portion of the valve is positioned in the inner bore 20 by lowering or pumping the plug down the inner bore 20 of the production string T which will pass through the larger diameter inner bore 20a portion but will seat on and be retained by shoulder 20b below the circulation channel 25. The plug controls communication of surface controlled increased inner bore pressure above the plug with the sensing channel 45 and the locking channel 55 as desired. The use of a ball 60 sealing the inner bore below the circulation channel is illustrated in FIG. 6 but a ball or plug sealing to and blocking the inner bore below the circulation channel 25 may be used. The plug 60 embodiment blocks communication of the inner bore above the plug with both the sensing channel 45 and the locking channel 55 and is used in opening the valve as will be described more fully hereinafter.

Another embodiment of the plug or means for controlling communication of pressure in the inner bore is a locking plug 61, illustrated in FIG. 7, having a shoulder 61a adapted to seat on shoulder 20b of the inner bore 20 and positioning the plug 61 in the inner bore 20. An O-ring 61b seals the plug to the inner bore 20c at a location between the locking channel 55 and the sensing channel 45 permitting the inner bore 20 above the plug 61 to communicate with the locking channel 55, but not permitting communication with the sensing channel 45. An outer groove 61c and an annular manifold opening 61d adjacent the locking channel 55 permit communication between locking channel 55, the circulation channel 25 and the inner bore 21 of the production tubing T above the plug 61. The sensing channel 45 is blocked by the plug 61 from communicating with the locking channel 55 and circulation channel 25 in addition to the inner bore 21 of the production tubing T above the plug. The plug 61 also blocks communication through the inner bore 20. A port 612 and blocking member 61d assists in the removal of the plug 61, as is well known in the art.

An unlocking plub 62, illustrated in FIG. 8, is another embodiment of the plug or means for controlling communication of pressure in the inner bore 20 above the plug and is positioned in the inner bore 20 by the shoulder 62a seating on the shoulder 20b of the inner bore 20 when the plug 62 is lowered in the tubing T. Plug 62 is sealed to the inner bore 200 between the circulation channel 25 and the locking channel 55 by O-ring 62b and between the locking channel 55 and the sensing channel 45 by O-ring 62c and again by O-ring 62d below the sensing channel 45. The unlocking plug 62 permits communication between the inner bore .20 above the plug 62 and the sensing channel 45, but blocks communication of the inner bore 20 above the plug with the locking channel 55. Channel 62c permits communication between the sensing channel 45, the circulation channel 25 and the inner bore 20 above the plug 62. Channel 62f permits communication from the locking channel 55 to the inner bore 20 below the sealing ring 62 d of plug 62. Communication between the inner bore 20 above the plug 62 to the inner bore 20 below the plug 62 is also blocked.

In the use and operation of the present invention with the single completion well, illustrated in FIG. 1, tubular member is connected in the production tubing T immediately above the packer P for sealing off the annulus 12 above the production zone and is lowered into the set perforated well casing 12 filled with drilling fluid as is well known in the art. At the desired location the packer P is set sealing the annulus 12 between the casing 11 and the production string T, as is well known in the art.

The valve 10 is assembled in the production tubing 10 in the condition illustrated in FIG. 4. With equal pressure in the inner bore 20 and the area immediately adjacent the exterior of the tool, the exterior pressure provides equal and offsetting urging on the sleeve 30, while the inner bore pressure communicated through circulation channel 25 and acting on shoulder 30j for moving the sleeve 30 to the open position, is at least balanced by the same inner bore pressure communicated through sensing channel 45 to the shoulder 40a of the movable sealing member 40. This allows the spring 41 to bias the sleeve to the closed position by the slide 40 engaging shoulder 30f of the sleeve 30 and moving the sleeve 30 to the closed position as the slide 40 moves to the lower position. This position blocks all communication of the inner bore 20 with the annulus 12 of the well through the valve. Should the pressure in the inner bore 20 become greater than the pressure immediately adjacent the exterior of the tool the greater pressure in the inner bore 20 will act on shoul' der 40a to maintain the slide 40 in the lower position and thereby the sleeve 30 in the closed position. As illustrated in FIG. 9, the bore 20 pressure responsive shoulder 40a and 30] may be provided with different size areas on which the pressure urges. By making the shoulder 40a larger than the shoulder 30j pressure in the bore 20 will urge the valve closed. In this manner the valve may be pumped closed should the spring 41 malfunction or break.

Lowering the production tubing T into the well casing 11 fills the inner bores 21 and 20 with drilling fluid through the tubing T open lower end and should cause the pressure in the annulus 12 to become greater than the pressure in the inner bore 20 because of the difference in heights of columns of drilling fluid. The greater pressure in the annulus 12 will maintain the sleeve 30 in the closed position, but the slide member 40 will move to the upper position illustrated in FIG. 5. The movable sealing member 40 has the greater pressure in the annulus 12 acting upwardly on the shoulder 40b while the pressure in the inner bore 20 is acting downwardly on shoulder 40a. Since the effective surface area of shoulders 40a and 40b on which these pressures act are equal, the slide member 40 will move upward. The upward movement of the movable sealing member 40 to a position spaced from the shoulder 30f permits the greater pressure in the annulus 12 to act on the entire shoulder 30f as a means for maintaining the sleeve 30 in the closed position in response to the greater pressure in the annulus 12. This also occurs in the embodiment illustrated in FIG. 9.

To complete the well permitting flow of hydrocarbons from the formation F, it is necessary to displace the heavy drilling fluid from the bore 21 of the production string T with a lower density fluid, as is well known in the art. As illustrated in FIG. 6, the plug or ball 60 for controlling communication in the inner bore 20 is placed in the production string inner bore 21 and is pumped or lowered until it seats on shoulder 20b positioning the ball 60 between the circulation channel 25 and the sensing channel 45. The pressure in the inner bore 20 above the plug or ball 60 is then increased by injecting the lower density fluid into the inner bore 21 of the production tubing T at the surface by a pump P or other fluid pressure generating means, as is well known in the art. The increased pressure above the plug 60 is communicated through the circulation channel 25 to the shoulder 30e where it urges on the shoulder 30c to overcome the pressure in the annulus 12 urging on shoulder 30f or the urging of the movable slide 40 and moves the sleeve 30 to the open position. This allows the heavy drilling fluid within the inner bore 20 of the production string T above the plug 60 to flow through the circulation channel 25 and the flow port 31 into the annulus 12 of the well above the packer P. The drilling fluid in the annulus 12 is removed from the well casing l 1 at the surface permitting the production string to fill with lighter fluid. When the production string T above the plug 60 is filled with lower density fluid above the blocking means 60, the pumps are stopped decreasing the pressure in the inner bore 20 above the ball or plug 60. When the pressure in the inner bore 20 decreases sufficiently to be substantially equal to the pressure in the annulus 12, the spring 41 closes the valve blocking flow from the inner bore 20 into the annulus 12. With the valve now closed, formation F pressure greater than the hydrostatic pres sure within the well casing 11 at the perforations allows the hydrocarbons to flow into the casing 11 through the perforations O and on to the surface through the inner bore 21 of the production tubing T, as is well known. in the art. Normally the blocking means 60 is retrieved by the formation pressure flowing the ball 60 to the surface where it is removed from the bore 21 completing the well. The ball 60 may be removed by smashing the ball 60 or by retrieving with a wire line, but the removal by formation pressure with retrieval at the surface is preferred.

To kill the single production zone well by filling the inner bore 21 of the production tubing T with a heavy fluid, the locking plug 61 is lowered down the production tubing inner bore 21 until it seats on shoulder b of the tubular member 10. The plug 61 communicates the inner bore 20 above the plug 61 with the circulation channel and the locking channel 55 while blocking communication past the plug 61. Surface pumps are then used to increase the pressure in the inner bore 21 of the production string T above the plug 61. This increased pressure is communicated to the inner bore 20 above the plug 61 and communicated through the circulation channel 25 to the shoulder a for moving the sleeve 30 to the open position. The pressure in the inner bore 20 above the plug 61 is also communicated by the plug 61 through locking channel 55 to the locking shoulder a of the latch member 50. The increased presure acting on shoulder 50a moves the latch member 50 downward, shearing pin 51, and moving the latch member 50 to the lower position, illustrated in FIGS. 7 and 8. In this position, the step shoulder 50b moves within the detent 52 locking it in the recess 30h of the sleeve 30 and thereby mechanically locking the sleeve 30 in the open position. The latch member 50b prevents the detent 52 from moving out of the recess 30h which would allow the valve to close. With the valve now mechanically locked open, the pumps are stopped. The surface pumps are then connected to the well casing 11 and are used to inject or introduce the heavier drilling fluid into the annulus 12 above the packer P. The heavier drilling fluid in the annulus 12 then back circulates from the annulus 12 above the packer P through flow port 31 and circulation channel 25 into the inner bore 20 above the plug 61 filling the inner bore 21 of the production tubing T. The lighter fluids displaced by the heavier drilling fluid are re moved from the inner bore 21 of the production tubing T at the surface. The heavier drilling fluid in the inner bore 21 establishes a greater hydrostatic head preventing flow of hydrocarbons from the formation through the perforations O in the casing 11 killing the well. Plug 61 may be removed at the surface when the tubing is pulled or retrieved by a wire line when the back circulation is complete and formation pressure is no longer within the tubing T inner bore 21.

To recomplete a single production zone killed well having a locked open sleeve valve, the locking plug 61 is removed and the cross over plug 62 is lowered down the inner bore 21 of production tubing T until it seats on shoulder 20b. The crossover plug 62 positioned in the inner bore 20 by shoulder 20b permits communications of the inner bore above the plug 62 with sensing channel 45 and the circulation channel 25. The locking channel 55 communicates with the inner bore 20 below the blocking plug 62, but is blocked from communicating with the inner bore above the plug 62. The plug 62 also blocks communication through the inner bore 20. The surface pumps are used to inject the light fluid into the inner bore 21 of the production tubing T. This increases the inner bore 20 pressure above the plug 62 in the open valve 10! and displaces the heavy drilling fluid below the lighter fluid through the circulation channel 25 and the flow port 31 into the annulus 12 of the well above the packer P and back to the surface where it is removed from the casing 11. The increased pressure in the inner bore 20 is also communicated through plug channel 62? and the sensing channel 45 to shoulder 50b of the latch member 50 for moving the latch 50 upward away from the detent 52 unlocking the sleeve 30 and freeing sleeve 30 to be moved to the closed position by the spring 41. Fluid on the upper side 50a of latch member 50 is vented into the inner bore 20 below the plug 62 by channel 62f preventing any trapped fluid from blocking movement of the latch member 50 to the upper position. Light fluid is pumped into the inner bore 21 until it fills all of the inner bore 21 above the plug 62. The pressure in the inner bore 21 is then decreased closing the valve 10. When the plug 62 is retrieved the hydrocarbons are free to flow into the casing 12 through the perforation O and on to the surface through the inner bore 21 of production tubing T as is well known in the art.

FIG. 2 illustrates use of the present invention in a dual completion well. The completion and kill valve 10 is placed in the lower zone production tubing T immediately above the packer P-l separating the upper and lower production zones. To complete the dual completion well, the plug is lowered down the inner bore 21 of the lower production zone tubing string T until it seats on the shoulder 20b in the inner bore 20 of the valve 10. Surface pumps are then used to inject or introduce a lighter density fluid into the production tubing inner bore 21 above the ball 60 while also increasing the pressure in the inner bore 20 above the ball 60 to open the valve 10. The displaced heavier drilling fluid is removed from the well at the surface through the inner bore 21 of the upper zone production tubing T-l. The lighter fluid is circulated from the inner bore 21 of the production tubing T through the circulation channel 25 into the upper production zone 12a, and through the inner bore 21. of the upper zone production tubing T-l to the surface. The pumps continue to introduce the light fluid until the inner bore 21 of the upper zone production tubing T is filled with lighter density fluid from the lower zone production tubing inner bore.

When the inner bore 21 of both tubings T and T-1 are filled with the light fluid, the pumps are shut down, lowering the pressure in the inner bore 20 above the plug 60 and allowing the spring 41 to move the sleeve 30 to the closed position. The pressure in the upper formation is then free to flow hydrocarbons through perforations in casing 11 into the area 12a and on to the surface through the inner bore of production tubing T-l.

The plug or ball 60 must be removed from the valve before the production tubing T can flow the lower formation hydrocarbons to the surface.

Use of the valve 10 in the killing of a dual completed well by filling the inner bore 21 of both production tubings T and T-l with a heavier fluid may be accomplished by two methods. In the first method, the step of the method of completing the dual zone well are repeated with two exceptions. The plug 60 lowered in the inner bore 21 of the production tubing T need not be removed to kill the well. The other change is that a heavy fluid is injected into the inner bore 21 of the lower zone tubing above the plug 60 and allowed to circulate through the valve 10 into the inner bore 21 of the upper zone production tubing T-1 and filling both inner bores 21 with the heavy fluid while the lighter fluid is removed from the inner bore 21 of the upper zone production tubing.

In the second method to kill a dual completion well, the locking plug 61is lowered down the inner bore 21 of the lower zone production tubing T to seat in the valve 10. The pressure in the inner bore 21 above the plug 62 is then increased to open and mechanically lock open the valve 10. Heavy drilling fluid is then injected into the inner bore 21 of the upper zone production tubing T-1 while removing the displaced lighter fluid from the inner bore 21 of the lower zone production tubing above the sleeve valve 10. The injection of the heavy drilling fluid is continued until the inner bores of both the upper and lower zone production tubings are filled with heavy drilling fluid thereby killing the well. i 1

FIG. 3 illustrates the use of the present invention in completing a three zone production well by displacing the heavy fluid in the inner bores of the production tubings. A packer P-l separates the lower zone from the middle zone while a packer P-2 separates the middle zone and the upper zone. The packer P-3 seals the annulus 12 above the upper zone. The bottom two zones are first completed by lowering the plug 60 in the inner bore 21 of the lower zone production tubing to seat in the inner bore of valve 10a and then injecting lighter fluid in the inner bore 21 of the lower zone production tubing T to increase the pressure above the plug 60 to thereby open the valve 10a. The displaced heavy drilling fluid is removed from the well through the inner bore 21 of the middle zone production tubing T-l. The injection of the lighter fluid above the plug 60 continues until the inner-bore 21 of the middle zone production tubing T-1 is filled with the lighter fluid. The pumps are shut down decreasing the pressure in the inner bore 21 of the lower zone production tubing closing valve 10a. A plug 60 is then lowered down the inner bore 21 of the middle zone production tubing T-luntil it seats in the valve 10b. Lighter fluid is then injected into the annulus 12b between packers P-2 and P3 and up the inner bore 21 of the upper zone production string T-2 to the surface. The heavy fluid within the well is removed through the inner bore 21 of the upper zone production tubing T-2. When the lighter fluid is circulating back to the surface through the upper zone production tubing T-2, the pumps are shut down decreasing the pressure in the inner bore of the middle zone production tubing T-l, closing the valve 10b. When the plugs 60 are removed, all three zonesare ready to produce and the well is completed.

To kill the triple producing zone well, a plug 60 is lowered down the inner bore 21 of the lower zone production tubing T until it seats on the shoulder b within the inner bore of valve 10a. The surface pumps are then used to introduce heavy drilling fluid at in-' creased pressure into the inner bore 21 of the production tubing T to open the valve 10a and circulate the heavy drilling fluid through the annulus 12a into the inner bore of middle zone production tubing T-l and back to the surface. The lighter fluid is removed from the well through the inner bore 21 of the middle zone production tubing T-l. This circulation fills the inner bore of the two lower production zones tubing T and T-l with heavy drilling fluid. Tokill the upper production zone, the plug 60 is lowered down the production tubing T-l until it seats on the shoulder 20b of valve 10b. Surface pumps are then used to introduce heavy drilling fluid into the inner bore 21 of the production tubing T-l at increased pressure. The increased pressure in the inner bore 20 of the middle zone production tubing T-l above the plug 60 opens the valve 10b circulating the heavier drilling fluid into the annulus 12b and back to the surface through the inner bore 21 of the upper zone production tubing T-2. The displaced] lighter fluid is removed from the well through the inner bore 21 of the upper zone production tubing T-2. Filling the inner bore 21 of the upper zone production tubat increased pressure into the inner bore 21 of the mid- 6 dle zone production .tubing T-l above the plug 60. This.

ing T-2 with the heavy fluidkills'the upper zone and completes the killing of the well.

From the multiple zone methods set out above it is The foregoingdisclosure and description of the invention are illustrative and explanatory thereof, and various changes in the size, shape and materials as well as in the details of the illustrated construction may be made without departing from the spirit of the invention.

What is claimed is;

1. A process for killing a single production zone well having a set well casing and a production tubing inner bore filled with lighter density fluids at formation pressure by displacing the lighter density fluids from the production tubing inner bore with a heavy fluid through a pressure responsive lockable open sleeve valve located in the production tubing above a packer comprising:

a. lowering a plug down the inner bore of the production string;

b. seating the plug in the sleeve valve;

c. increasing the pressure of the fluid in the production tubing inner bore above the plug for opening and locking open the valve;

d. injecting heavy fluid into the well casing above the packer;

e. removing the displaced lighter density fluids from the production tubing inner bore above the sleeve valve; and

f. substantially filling the inner bore of the production tubing with the heavier fluid wherein the well is killed.

2. A process for killing two production zones of a well having a set well casing and an upper zone and a lower zone production tubing having inner bores therein filled with lighter density fluids at formation pressure by displacing the lighter density fluids from the production tubing inner bores with a heavy fluid through a pressure responsive sleeve valve located in the lower zone production tubing above a packer separating the upper and lower zones comprising:

a. lowering a plug down the inner bore of the lower zone production string;

b. seating the plug in the sleeve valve;

0. injecting a heavy fluid into the inner bore of the lower zone production tubing above the plug;

d. increasing the pressure of the fluid in the lower zone production tubing inner bore above the plug for opening the sleeve valve;

e. removing the displaced lighter fluid from the well through the upper zone production tubing inner bore; and

f. substantially filling the upper zone production tubing inner bore with heavy fluid from the lower zone production tubing inner bore.

3. A process for killing two production zones of a well having a set well casing and an upper zone and a lower zone production tubing having inner bores therein filled with lighter density fluids at formation pressure by displacing the lighter density fluids from the production tubing inner bores with heavy fluid through a pressure responsive lockable open sleeve valve located in the lower zone production tubing above a packer separating the upper and lower zones comprising:

a. lowering a plug down the inner bore of the lower zone production string;

b. seating the plug in the sleeve valve;

c. increasing the pressure of the fluid in the production tubing inner bore above the plug for opening and locking open the valve;

d. injecting heavy fluid into the inner bore of the upper zone production tubing;

e. removing the displaced lighter density fluids from the lower zone production tubing inner bore above the sleeve valve;

f. substantially filling the upper zone production tubing inner bore with heavy drilling fluid;

g. substantially filling the lower zone production tubing inner bore with heavy drilling fluid from the upper zone production tubing inner bore communicated through the locked open sleeve valve wherein the well is killed.

4. A process of killing a well having a production tubing by displacing a lighter fluid within the bore of the production tubing with a heavy fluid using a valve connected in the production tubing and operably responsive to the application of a controlled fluid pressure for providing a circulation channel communicating the bore of the production tubing with the area adjacent the exterior of the valve, including the steps of:

a. positioning a plug in the bore of the production tubing to control the application of fluid pressure to the valve;

b. controlling the fluid pressure in the well applied to the valve to establish a circulation channel for communicating through the production tubing; and

c. injecting heavy fluids into the bore of the production tubing for displacing the lighter fluids with the heavy fluids wherein the well is killed.

5. The method as set forth in claim 4, including the step of:

removing the displaced lighter fluids from the bore of the production tubing through the circulation channel of the valve to kill the well.

6. The method as set forth in claim 4, including the step of:

filling the bore of the production tubing with sufficient heavy fluids to kill the well.

7. The method as set forth in claim 4, including the step of:

locking the valve in the open condition for providing the circulation channel to enable communication between the bore of the production tubing and the area adjacent the exterior of the valve when the controlled application of fuid pressure to the valve is removed.

8. The method as set forth in claim 7, including the step of:

injecting the heavy fluids into the bore of the production tubing through the circulation channel wherein the well is killed.

9. The method as set forth in claim 8, including the step of:

flowing the heavy fluids to a location in the well adjacent the circulation channel for injecting into the bore of the production tubing through the circulation channel.

10. The method as set forth in claim 8, including the step of:

flowing the heavy fluids through the bore of a second production tubing positioned in the well to a location in the well adjacent the circulation channel for injection into the bore of the first mentioned production tubing through the circulation channel wherein the first mentioned production tubing well and the second production tubing well are killed.

11. A process for killing a well having a production tubing with an bore filled with lighter density fluid by displacing the lighter density fluids from the bore of the production tubing with heavy fluids by using a pressure responsive lockable open valve located in the production tubing and responsive to an application of a controlled fluid pressure for providing a circulation channel through the production tubing, comprising the steps of:

lowering a plug down the bore of the production string for seating to control application of fluid pressure to a desired portion of the valve;

increasing the pressure of the fluid in the bore of the production tubing for controlled application to the valve for opening the valve to form the circulation channel and locking open the valve; and,

filling the bore of the production tubing with sufficient heavier fluids wherein the well is killed. 12. The method as set forth in claim 11, including the step of:

injecting the heavy fluids in the bore of the production tubing through the circulation channel for substantially filling the bore of the production tubing.

removing the lighter density fluids displaced by injecting the heavy fluids from the bore of the production tubing through the circulation channel.

15. The method as set forth in claim 12, including the step of:

flowing the heavy fluids through a well casing to a location adjacent the circulation channel for injection into the bore of the production tubing through the circulation channel.

16. The method as set forth in claim 12, including the step of:

flowing the heavy fluids through the bore of a second production tubing to a location adjacent the circulation channel for injection into the bore of the first mentioned production tubing through the circulation channel wherein the first mentioned production tubing well and the second production tubing 

1. A process for killing a single production zone well having a set well casing and a production tubing inner bore filled with lighter density fluids at formation pressure by displacing the lighter density fluids from the production tubing inner bore with a heavy fluid through a pressure responsive lockable open sleeve valve located in the production tubing above a packer comprising: a. lowering a plug down the inner bore of the production string; b. seating the plug in the sleeve valve; c. increasing the pressure of the fluid in the production tubing inner bore above the plug for opening and locking open the valve; d. injecting heavy fluid into the well casing above the packer; e. removing the displaced lighter density fluids from the production tubing inner bore above the sleeve valve; and f. substantially filling the inner bore of the production tubing with the heavier fluid wherein the well is killed.
 2. A process for killing two production zones of a well having a set well casing and an upper zone and a lower zone production tubing having inner bores therein filled with lighter density fluids at formation pressure by displacing the lighter density fluids from the production tubing inner bores with a heavy fluid through a pressure responsive sleeve valve located in the lower zone production tubing above a packer separating the upper and lower zones comprising: a. lowering a plug down the inner bore of the lower zone production string; b. seating the plug in the sleeve valve; c. injecting a heavy fluid into the inner bore of the lower zone production tubing above the plug; d. increasing the pressure of the fluid in the lower zone production tubing inner bore above the plug for opening the sleeve valve; e. removing the displaced lighter fluid from the well through the upper zone production tubing inner bore; and f. substantially filling the upper zone production tubing inner bore with heavy fluid from the lower zone production tubing inner bore.
 3. A process for killing two production zones of a well having a set well casing and an upper zone and a lower zone production tubing having inner bores therein filled with lighter density fluids at formation pressure by displacing the lighter density fluids from the production tubing inner bores with heavy fluid through a pressure responsive lockable open sleeve valve located in the lower zone production tubing above a packer separating the upper and lower zones comprising: a. lowering a plug down the inner bore of the lower zone production string; b. seating the plug in the sleeve valve; c. increasing the pressure of the fluid in the production tubing inner bore above the plug for opening and locking open the valve; d. injecting heavy fluid into the inner bore of the upper zone production tubing; e. removing the displaced lighter density fluids from the lower zone production tubing inner bore above the sleeve valve; f. substantially filling the upper zone production tubing inner bore with heavy drilling fluid; g. substantially filling the lower zone production tubing inner bore with heavy drilling fluid from the upper zone production tubing inner bore communicated through the locked open sleeve valve wherein the well is killed.
 4. A process of killing a well having a production tubing by displacing a lighter fluid within the bore of the production tubing with a heavy fluid using a valve connected in the production tubing and operably responsive to the application of a controlled fluid pressure for providing a circulation channel communicating the bore of the production tubing with the area adjacent the exterior of the valve, including the steps of: a. positioning a plug in the bore of the production tubing to control the application of fluid pressure to the valve; b. controlling the fluid pressure in the well applied to the valve to establish a circulation channel for communicating through the production tubing; and c. injecting heavy fluids into the bore of the production tubing for displacing the lighter fluids with the heavy fluids wherein the well is killed.
 5. The method as set forth in claim 4, including The step of: removing the displaced lighter fluids from the bore of the production tubing through the circulation channel of the valve to kill the well.
 6. The method as set forth in claim 4, including the step of: filling the bore of the production tubing with sufficient heavy fluids to kill the well.
 7. The method as set forth in claim 4, including the step of: locking the valve in the open condition for providing the circulation channel to enable communication between the bore of the production tubing and the area adjacent the exterior of the valve when the controlled application of fuid pressure to the valve is removed.
 8. The method as set forth in claim 7, including the step of: injecting the heavy fluids into the bore of the production tubing through the circulation channel wherein the well is killed.
 9. The method as set forth in claim 8, including the step of: flowing the heavy fluids to a location in the well adjacent the circulation channel for injecting into the bore of the production tubing through the circulation channel.
 10. The method as set forth in claim 8, including the step of: flowing the heavy fluids through the bore of a second production tubing positioned in the well to a location in the well adjacent the circulation channel for injection into the bore of the first mentioned production tubing through the circulation channel wherein the first mentioned production tubing well and the second production tubing well are killed.
 11. A process for killing a well having a production tubing with an bore filled with lighter density fluid by displacing the lighter density fluids from the bore of the production tubing with heavy fluids by using a pressure responsive lockable open valve located in the production tubing and responsive to an application of a controlled fluid pressure for providing a circulation channel through the production tubing, comprising the steps of: lowering a plug down the bore of the production string for seating to control application of fluid pressure to a desired portion of the valve; increasing the pressure of the fluid in the bore of the production tubing for controlled application to the valve for opening the valve to form the circulation channel and locking open the valve; and, filling the bore of the production tubing with sufficient heavier fluids wherein the well is killed.
 12. The method as set forth in claim 11, including the step of: injecting the heavy fluids in the bore of the production tubing through the circulation channel for substantially filling the bore of the production tubing.
 13. The method as set forth in claim 12, including the step of: removing the lighter density fluids displaced by injecting the heavy fluids from the bore of the production tubing at a location above the circulation channel.
 14. The method as set forth in claim 11, including the steps of: injecting the heavy fluids in the bore of the production tubing at a location spaced from the circulation channel; and, removing the lighter density fluids displaced by injecting the heavy fluids from the bore of the production tubing through the circulation channel.
 15. The method as set forth in claim 12, including the step of: flowing the heavy fluids through a well casing to a location adjacent the circulation channel for injection into the bore of the production tubing through the circulation channel.
 16. The method as set forth in claim 12, including the step of: flowing the heavy fluids through the bore of a second production tubing to a location adjacent the circulation channel for injection into the bore of the first mentioned production tubing through the circulation channel wherein the first mentioned production tubing well and the second production tubing well are killed. 